Field of the Invention
This invention relates to an integration of a hydraulic workover or “snubbing” unit and a coil tubing unit with applications including drilling, completion, well workovers and well control. Unique features of the system are: the ability to vertically stand multiple joints and pipe near the unit as opposed to laying down each joint as done in conventional operations, the combined capability of a hydraulic workover or “snubbing” unit and a coiled tubing unit in one piece of equipment, the ability to run jointed pipe in combination with coil tubing, the ability to run coil tubing in combination with jointed pipe, the use of a single hydraulic power pack to operate the jack and/or coil tubing unit, and the ability to circulate fluid while rotating and reciprocating the pipe or coiled tubing.
Various prior art inventions of interest are as follows:
U.S. Pat. No. 5,738,173, to Burge et al.(Baker Hughes), describes apparatus for and method of installing both tubing and pipe in a well. U.S. Pat. No. 4,515,220, to Sizer et al. (Otis Engineering), describes apparatus for and method of installing both coiled tubing and also jointed pipe in a well. U.S. Pat. No. 4,655,291, to Cox (Otis Engineering), shows apparatus and method for installing both coiled tubing and also jointed pipe in a well. U.S. Pat. No. 5,244,046, to Council et al. (Otis Engineering), shows a tubing injecting unit adapted to install both tubing and also wireline tools into a well. U.S. Pat. No. 5,094,340, to Avakov (Otis Engineering), sets forth gripping blocks adapted to handle coiled tubing, jointed pipe, and still other elongate objects for installation in a well.
Other related art is disclosed in Patent Numbers U.S. Pat. No. 3,191,450, to Wilson, U.S. Pat. No. 3,215,203, to Sizer, U.S. Pat. No. 3,285,485, to Slator, U.S. Pat. No. 3,313,346, to Cross, U.S. Pat. No. 3,559,905, to Palynchuk, U.S. Pat. No. 3,677,345, to Sizer, U.S. Pat. No. 3,754,474, to Palynchuk, U.S. Pat. No. 4,085,796, to Council, U.S. Pat. No. 4,251,176, to Sizer, U.S. Pat. No. 4,515,220, to Sizer, Cox and Council, which along with U.S. Pat. No. 5,738,173, to Burge, U.S. Pat. No. 4,515,220, to Sizer, U.S. Pat. No. 4,655,291, to Cox, U.S. Pat. No. 5,244,046, to Council, U.S. Pat. No. 5,094,340, to Avakov, are hereby fully incorporated by reference for all they disclose.
The above art illustrates conventional coiled tubing operations, which like conventional jointed pipe drilling has certain deficiencies. Coiled tubing used in drilling applications can not be rotated without rotating the reel, guide arch and injector about the centerline of the well or cutting the coiled tubing and installing a connector to permit rotating the pipe then in the hole. In the former case, string rotational speed is limited to the safe rotational speed of the entire bulky assembly. In the latter situation, the coiled tubing cannot be rotated and run into or pulled out of the hole simultaneously. The absence of rotational capability requires the use of a down hole motor to drill and an orienting tool downhole to adjust toolface position during directional drilling.
The coiled tubing must be cut, and a connector installed, each time a piece of “jewelry” is added to the drillstring above the bottomhole assembly. Each such item must be removed before the pipe can be spooled onto the reel unless the item is specifically designed to be spoolable. Each time a connector is added to a coiled tubing string, a stress raiser is intentionally applied in the continuous pipe string, which reduces both string utility in other applications and string life in general.
Coiled tubing reels and support structures are heavy. The combined weight of a fully loaded spool may exceed platform crane rated capacity requiring an upgrade or a separate “bull frog” crane on some platforms to lift the reel into place for coiled tubing drilling. This is even more important as coiled tubing diameters and wall thicknesses increase for deeper drilling applications, the current trend. Lifting such heavy loads with limited cranes increases the potential for accidents including damage to equipment and injuries to personnel.
Jointed pipe drilling requires excessive time to trip drillpipe for changes to the string or drilling tools. A derrick or other structure is required to provide hoisting and racking capabilities for jointed-tubing tripping with attendant weight, space and maintenance requirements.
Jointed-pipe handling is discontinuous. Stopping and starting is required for each connection make-up or breakout required. Multiple steps are required for each such connection make-up or breakout required, each of which places operating personnel at some risk. Further, multiple equipment functions are required which relates to wear, maintenance, replacement and cost. Failure is possible at each point, any one of which can shut down operations for varying time periods.
The present invention achieves several advantages and improvements over conventional prior art methods and apparatus. Jointed drillpipe can be delivered in small units with weights far less than the combined weight of a loaded coiled tubing reel. Only one large reel is needed for the system instead of several when large diameter drillpipe is used for drilling deep wells. This reel is only used for tripping the drillpipe, not for shipment. The reel alternatively is in multiple pieces that are assembled on-site instead of a single large unit, or the reel may be a single collapsible unit that is expanded on-site. Either of these removes shipping complications associated with a large-diameter reel and support structure.
Pipe is unscrewed, straightened and shipped back in basket-sized units after its last use in the well. Similarly the reel is either dismantled or re-collapsed for shipment after the job.
Improvements in operation are also achieved. The pipe, once run in the hole in “singles,” can be reeled out of the hole, then back in, without breaking apart except as needed. This reduces trip time associated with jointed-pipe systems and overall cost. Drillpipe tripping is a continuous process, which reduces the potential for differential sticking while tripping. Well control issues are simplified since monitoring for kicks, filling the hole and observing fluid levels are also continuous processes. Well control measures can be enacted quickly since the spoolable drillpipe is always connected to the pump through the reel swivel. Pumping can be initiated without positioning a drillpipe body across a blow out preventer and stabbing a kelly or valve onto an open drillpipe connection. If flush joint or non upset external tubing spoolable drillpipe is used, blow out preventors can be activated even if a joint is situated in the rams.
With the present invention, a derrick or other support system for hoisting jointed pipe and racking it back is not required. Pipe can be unscrewed and disconnected from the reel at any connection allowing the entire string to be rotated and raised or lowered by adding or removing single joints. Thus, the system can go from continuous (reeled) to jointed at any time. The pipe can be rotated while drilling to orient downhole directional tools since the spoolable feature is generally only used for tripping, although drilling with a downhole motor is possible. During drilling, the system is a jointed-pipe operation. The entire string can be rotated at common speeds (RPMs) so it need not rely entirely on downhole motors for supplying rotation to the bit.
With the present invention, make-up and break-out equipment is used less frequently than with conventional jointed-pipe systems reducing maintenance, pipe-handling, replacement and personnel risk issues and, thus, costs. Personnel are not overly fatigued if multiple trips are required during a single tour, particularly at moderate to extended depths. Fewer steps with less intensive physical strength are required for tripping which will probably result in fewer injuries and work-related illnesses. Fewer crew members may be required. Automation or computer-assist systems can be incorporated with this system including real-time monitoring, level wind assist, pipe tensioning, etc. for improved efficiency with resultant cost reductions. This improved system can be used in either drilling or reworking operations on existing wells.
In summary, deficiencies of conventional hydraulic workover operations without a derrick are: each joint must be unscrewed from every other joint; it is not possible to continuously circulate while tripping; pipe handling is required to lay down each joint as it is pulled from the hole, which involves wear on hoisting equipment and some risk to personnel; trip time is slow in view of the above; and, a structure is required of sufficient area size and strength to hold and support the dry weight of pipe removed from the hole.
Deficiencies of conventional coiled tubing drilling are: lack of rotation; continual slide mode; excessive weight of tubulars and coil tubing reel; short tubular life due to the effects of low cycle fatigue; reduced capabilities in running jointed tubulars (bottom hole assemblies, and completions); non-competitive day rates; decreased penetration rates vs. hydraulic workover unit or rig due to lower weight on bit and inability to overcome friction; lower hydraulic efficiencies vs. conventional tubing due to reduced coiled tubing sizes; lesser hole cleaning capabilities; and, higher cost of pumping equipment due to lower hydraulic efficiencies.
It is thus desirable to combine advantages of coil tubing: continuous pumping while tripping; underbalanced drilling; faster trip time versus hydraulic workover unit or rig; smaller footprint vs. rig; less personnel required; and, reduction of personnel time required to work on a platform close to well with those of a hydraulic workover unit: the ability to rotate during all facets of job including underbalanced drilling and while tripping pipe; the ability to use segmented components better suited for existing crane capacities; running larger tubulars; running completion strings; greater hook loads; the ability to convey different diameter tubulars; a smaller footprint vs. rig or coiled tubing unit since some of the equipment is on the well; higher hydraulic efficiencies; greater hole cleaning capabilities; higher pressure capabilities for comparable tubulars; and, longer tubular useful life vs. coil tubing unit.
Previous attempts to combine some of hydraulic workover and coiled tubing operations also had deficiencies. Jointed pipe had to be handled by the snubbing unit while the coiled tubing injector is rigged down or “trollied” off the well centerline. Injector head lifting or snubbing force capacities were less than those of the snubbing unit in most cases which, in turn, limited the depth to which large-diameter coiled tubing could be run. With previous attempts and apparatus the coiled tubing must be cut to rig down or trolley the injector head out of the way. Excessive time is required to run or pull combinations of externally-upset end (EUE) jointed pipe and coiled tubing with prior apparatus since the injector must be rigged down or moved each time an EUE goes into or out of the well. This results in higher costs than using coiled tubing alone.
In summary, the present invention achieves the following improvements: EUE jointed pipe, non-upset jointed pipe and continuous pipe can be handled with a single unit, which does not require the coiled pipe to be cut to go from one pipe type to another.
In the event the injector head mechanically fails during a job, the coiled tubing can be run or pulled using the hydraulic jack. Similarly, if the jack fails, coiled tubing operations can continue (but jointed tubing operations can not). The injector head of the present invention does not need to be rigged down on trollied off the well centerline as a unit. Instead, the head splits apart with each half being moved back only the distance required for an EUE and collar on jointed pipe to clear the chains. The injector can be moved back into place hydraulically by the operator from the control console. This reduces time, risk to personnel and overall job cost to the customer.
Controls can be integrated so that a single operator can operate all system functions without switching from one piece of equipment to another. In other words, hydraulic workover operations can be replaced by coiled tubing operations by simply moving to a different set of control handles. A single power pack (hydraulic pump and engine) can be used for both operations instead of a separate one for each function, since when one system is in use, the other will not be under normal circumstances. However, both can be used simultaneously in other situations (jack assist of the coiled tubing injector to pull a heavy load, for example).
Well control equipment, blowout preventers (BOPs) and valves, for both equipment sets can be manifolded together using the same accumulator system so that either one or both can be functioned in the event of a well control incident.
The jack of the present invention is equipped with a rotary drive mechanism that can turn the entire pipe string as long as the coiled tubing is not connected to the reel. This provides the means to reduce trip time for jointed sections by allowing pipe to be “rotated out of the hole” (i.e., the top pipe can be held stationary and the bottom segment in the well can be rotated clockwise to unscrew right-hand threads and break the connection between pipe segments).
Jointed members can be snubbed into and out of the hole under pressure. This obviates killing the well to pull jointed tubulars such as bottomhole assemblies, a current requirement of conventional coiled tubing drilling. Thus, the well can be maintained in an underbalanced situation throughout the drilling process. Completion equipment, including jointed production tubing, packers, profile nipples, blast joints, on-off tools, gravel pack screens, landing nipples, etc. can be run with the jack following coiled tubing operations such as drilling, recompletions or workovers without killing the well.
The present invention may also include a “rack-back” system. If so, multiple joints can be stood back, which reduces the number of joint breaks required in conventional hydraulic workover, tubing is not laid down; rather it is stood back vertically in fingerboards in multiple joint sections reducing hoisting equipment wear and personnel risk, and trip time is reduced along with overall operation cost.
Dry tubing weight can be supported by the earth, the platform or the wellhead depending on which base is used for standing the tubing. This allows its use on minimal structures lacking “normal” support capabilities such as: offshore satellite (monopod) platforms; old, physically damaged or corroded platforms; and, inshore well protection structures (i.e., no platform).
With this added rack back system component, a supplemental structure such as a barge, lift boat, offset platform or other structure is not required to hold the horizontal tubing segments since the pipe is stood almost vertically in the wellbore vicinity. This may reduce overall job costs, and fewer opportunities exist for tubular damage due to handling which reduces equipment replacement costs and economic risk to the customer (i.e., fewer threads are exposed to damage during breakout, hoisting and laydown operations).
With the added components comprising a spoolable drillpipe system, jointed drillpipe can be delivered in small units with weights far less than the combined weight of a loaded coiled tubing reel. Only one large reel is needed for the system instead of several when large diameter drillpipe is used for drilling deep wells. This reel need only used for tripping the drillpipe, not for shipment. The reel is in multiple pieces that are assembled on-site instead of a single large unit. Alternatively, the reel would be a single collapsible unit that is expanded on-site. Either of these removes shipping complications associated with a large-diameter reel and support structure. Pipe is unscrewed, straightened and shipped back in basket-sized units after its last use in the well. Similarly the reel is either dismantled or recollapsed for shipment after the job.